Reservoir simulation is an area of reservoir engineering that employs computer models to predict the flow of fluids, such as petroleum, water, and gas, within a reservoir. Reservoir simulators are advantageously employed by petroleum producers in determining how best to develop new fields, as well as in connection with developed fields in generating production forecasts on which investment decisions are based.
Fractured reservoirs present special challenges for simulation because of the multiple porosity systems or structures that may be present in these types of reservoirs. Various types of dual-porosity formulations have evolved for modeling these types of reservoirs. Some formulations are appropriate for high fracture densities, while other formulations are more appropriate for low fracture densities. Usually fracture density is highly variable between zones of a reservoir or among different reservoirs undergoing simultaneous simulation. Fractured reservoirs are traditionally modeled by representing the porous media using two co-exiting pore volumes interconnected by flow networks. One type of pore system, referred to as matrix and defined with matrix nodes, is characterized by high pore volume and low conductivity. Another type of pore system, referred to as fractures defined with fracture nodes, is characterized by low pore volume and high conductivity.
Those of ordinary skill in the art will appreciate that “nodes” as used herein refer to an elemental representation of pore volume within a simulated reservoir, while “zones” refer to a collection of all the nodes within a portion of the simulated reservoir. Finally, “grid” or “subgrid” as used herein refers to a subset of the nodes within a zone. Unknowns such as pressures and composition are solved for, on a node by node basis, at desired time increments.
In one common prior art simulated representation of a reservoir, referred to as dual-porosity, single-permeability (“DPSP”), matrix nodes communicate only with fracture nodes. In DPSP, fracture nodes can also communicate with other fracture nodes. In another common simulated prior art representation of a reservoir, referred to as dual-porosity, dual-permeability (“DPDP”), matrix nodes communicate with both fracture nodes and other matrix nodes. Typically, in prior art simulated representations of a reservoir, the simulation characterizes the reservoir as either a DPSP or a DPDP and uses the characterization throughout the simulation process. These prior art techniques essentially treat fracture areas and fracture free areas the same by characterizing the formation as homogenous throughout, and thus, fail to accurately portray a reservoir.
Moreover, in some reservoirs, particularly carbonate reservoirs, a third type of pore system, referred to as “vugs,” are prevalent. Vugs are pore spaces that are typically larger than pore spaces of the matrix. Vugs may or may not be connected to one another. Separate vugs are interconnected only through the interparticle porosity, i.e., the matrix porosity, and are not interconnected to one another as are matrix pore volumes and fracture pore volumes. As such, the fluid retention and transport properties of vug pore volumes are different from those of both the matrix and fractures. Thus, in addition to the drawback of characterizing dual porosity systems as either DPSP or DPDP, typically, dual-porosity formulations used in simulators of the prior art only account directly for fracture porosity and matrix porosity. The influence of vugs on liquid flow through a reservoir is represented indirectly and in a very approximate fashion, if at all.
What is needed is a flexible simulator framework that can more accurately accommodate varying fracture density pore volumes, namely, hybrid dual formulations, while maintaining optimal efficiency.